It is well known in the petroleum industry that after a bore hole has been completed, there are occasions when corrosive fluids in the bore hole must be kept out of contact with the well pipe casing because of the rapid destruction of the well pipe casing and the inability to replace the casing either practically or economically. In order to protect that portion of the well casing that is immersed in such fluids, well packers have been developed which are lowered down the well casing to a given point and then set in the casing so as to cause a fluid seal in the casing, sealing off that portion of the corrosive fluid below the packer from the well casing above the packer. Since the drill string extends through the packer to the portion of the well fluid below the packer, fluids below the packer can be pumped through the drill string to the surface, thus protecting the well casing above the packer from the corrosive fluids.
Well packers are associated with a cylindrical mandrel attached to the lower end of the drill string. The mandrel in the prior art is inserted through the hollow well packer and has formed on each side thereof a J-shaped slot which engages a gudgeon pin in the surrounding anchor cage that forms a part of the well packer. The anchor cage also has spring loaded friction pads spaced around the outside thereof, generally 90 apart, which engage the inside of the well casing and temporarily hold the well packer in a fixed position with respect to the well casing. The friction pads can support 200-300 pounds of weight without sliding. A gudgeon pin attached to and extending through opposite sides of the anchor cage engages a corresponding one of the J-slots. When the gudgeon pin is in the bottom portion of the J-slot, it is trapped and, by forcing the drill string downward, the packer is forced down into the well casing sliding the friction pads along the inside surface thereof.
When the proper depth at which the packer is to be set is reached in the bore hole, the friction pads hold the packer while the drill string is lifted slightly which releases each gudgeon pin from its trapped position at the bottom of the J-slots. By rotating the drill string slightly, the gudgeon pin is moved into the vertical section of the J-slot. The drill string can then be let down and the gudgeon pin travels upwardly in the J-slot. Forming a part of the mandrel, on the external surface thereof, is a band of threads or teeth. In like manner, on the anchor cage which contains the gudgeon pins are several arcuate segments of gear teeth that are urged inwardly against the mandrel by a resilient device such as a spring or springs. As the mandrel moves downwardly through the packer, the ratchetable teeth on the anchor cage slide over the band of teeth on the mandrel. The teeth are ratchetable in only one direction. As the mandrel moves downwardly with respect to the packer (which is being held in place by the friction pads) the teeth can ratchet with respect to each other. When the teeth are securely caught in locked engagement, the drill string is then pulled upwardly. A series of pivotable locking teeth in a lower slip assembly are forced outwardly against the well casing by a cam as the anchor cage moves upwardly. These teeth are angled so as to prevent the anchor cage from moving downwardly in the well casing, but does not prevent it from moving upwardly. As the mandrel continues to move the anchor cage upwardly, elastomer seals on the packer are compressed and a second cam on the upper side of the seals forces another set of locking teeth in an upper slip assembly outwardly into the well casing to prevent upward movement of the upper slip in which the upper teeth are mounted. Continued upward movement of the drill string compresses the entire unit because the upper slip assembly is now anchored by the locking teeth therein and will not move further upwardly. The lower teeth are engaged with the casing and will not allow the packer to move downwardly. The elastomer seals are compressed outwardly to engage the well casing and a fluid-tight seal is formed which prevents fluid below the packer from entering the well casing above the packer. Fluid in the well casing below the packer can be taken to the surface through the mandrel and the drill string.
When it is desired to remove the packer, the drill string has to be rotated in order to thread the latching teeth on the anchor cage off of the fixed teeth on the mandrel. Thus, it requires a considerable number of revolutions of the drill string to thread the anchor cage ratchetable teeth off the fixed mandrel teeth and, if the drill string should for any reason slip downwardly during the rotation, the ratchetable teeth simply slip over or ratchet across the fixed teeth on the mandrel and the process has to be started again.
The present invention overcomes the disadvantages of the prior art by providing a hydraulically operated well packer that automatically sets the packer in the well casing at the predetermined depth in the well casing when hydraulic pressure of a predetermined amount is supplied to the interior of the drill string. A mandrel is coupled to the end of the drill string and extends through the hollow well packer in a liquid sealing relationship. The packer includes upper and lower slip assemblies, each having pivotable teeth thereon for engaging the well casing when pivoted outwardly to lock the packer assembly in a fixed position in the well casing. At least one elastomer seal is positioned between the upper and lower slip assemblies. A hydraulic assembly is coupled to the upper and lower slip assemblies for compressing the at least one elastomer seal between the upper and lower slip assemblies to force the elastomer seal into a fluid sealing relationship with the well casing. Simultaneously, the hydraulic assembly forces the upper and lower slip assembly teeth into a gripping relationship with the well casing to rigidly set the packer in the casing.
A hydraulic piston is coupled to the lower slip for moving the lower slip along the mandrel toward the upper slip to compress the elastomer seals. Upper and lower cone assemblies are mounted respectively on the mandrel between the at least one elastomer seal and the slip teeth of the corresponding slip assemblies. Sloping surfaces on the upper and lower slip teeth engage a corresponding one of the cone assemblies as the lower slip is moved toward the upper slip which forces the lower teeth outwardly against the well casing and then forces the upper teeth outwardly against the well casing to rigidly set the packer.
The hydraulic piston assembly includes a first piston and a sleeve coupling the first piston to the lower slip assembly, with the first piston being selectively moveable from a first position to a second position to carry the lower slip assembly upwardly around the mandrel toward the upper slip assembly to compress the elastomer seals and force the upper and lower slip assembly teeth into gripping relationship with the well casing. The first piston is releasably locked in its first position and is enabled to move upwardly to its second position in response to a predetermined hydraulic pressure. A latch pin engages both the first piston and the mandrel to lock the first piston to the mandrel in its first position. A second piston is associated with the latch pin to hold the latch pin in engagement with the first piston and the mandrel. The second piston has a shear pin extending into a slot in the mandrel to lock the second piston to the mandrel. An orifice couples the interior of the mandrel to the first piston, the latch pin and the second piston and selectively provides hydraulic fluid under pressure to the first and second pistons and the latch pin. When sufficient hydraulic pressure is supplied to the orifice from the interior of the mandrel, the shear pin between the second piston and the mandrel breaks to enable the second piston to move away from and release the latch pin from engagement with the mandrel. The hydraulic pressure can then move the first piston in the upward direction to set the packer in the well casing.
An elongated arcuate section of teeth are integrally formed on opposing sides of the mandrel. Ratchetable arcuate segments of teeth are mounted on opposing sides of and carried by the cylindrical sleeve in radial alignment with corresponding ones of the mandrel arcuate teeth segments such that when the cylindrical sleeve moves upwardly carrying the lower slip assembly, the ratchetable teeth segments slip over and engage the teeth on corresponding ones of the elongated arcuate segments of teeth on the mandrel to lock the packer to the mandrel and prevent the cylindrical sleeve from slipping backwards. The arcuate segments of teeth on the mandrel and the cylindrical sleeve can be disengaged by rotating the mandrel no more than one-quarter turn because the arcuate sections of teeth on both the mandrel and the cylindrical sleeve are 60.degree. arcuate segments. By rotating the mandrel no more than 90.degree., the two segments disengage from each other and allow the well packer to be released from its engagement with the well casing. Thus, there are no J-slots on the improved mandrel, the mandrel does not have to be moved to set the packer and there are no frictional shoes on the well packer to hold it in place while the packer is being set.
Thus, it is an object of the present invention to provide a hydraulically operated well packer.
It is also an object of the present invention to provide a hydraulically operated well packer that includes a piston associated with a mandrel which is latched to and carried by the mandrel until hydraulic pressure of a sufficient amount is applied to the piston which releases it from the mandrel and enables it to carry a lower slip housing towards an upper slip housing to compress elastomer seals positioned between the slip assemblies and which sets the teeth in the upper and lower slip assemblies into engagement with the well casing to set the packer.